Background
The demand for crude oil has exceeded the existing production in the United States for more than 30 years. This has led to increasing demand for more imported oil and a dependency on foreign suppliers. The growth of emerging economies is rapidly increasing the demand for oil in the global market. It has been estimated that more than half of all conventional oil (oil that can be produced with current technology) has been produced. Most of the remaining conventional oil is located in the Eastern Hemisphere or in environmentally sensitive areas such as the North Pole. The lack of conventional oil supplies could keep oil prices so high that oil dependent nations such as the United States would be unable to fund the development of alternative energy technologies and be forced into dependency on foreign alternative energy as well. Therefore any new technology that could increase the efficiency of oil recovery would be of great benefit to countries such as the U.S. that have large amounts of unrecoverable oil in place (OIP) in older exiting oil fields.
Most oil fields are small and are spread out in the 600 or so sediment basins throughout the world. Most of these oil-producing basins have been explored. Generally the largest fields are discovered first, and further exploration finds only smaller reservoirs. Most of the world's petroleum is found in large fields. Only 37 supergiant oil fields of over 5 billion barrels have been found. These 37 fields account for 80% of all the known oil. Only two of these supergiants are in North America and 26 are in the Persian Gulf Most of the remaining undeveloped oil in the Western Hemisphere is not light petroleum, but is heavy oil or tar sands. Large deposits of heavy oil are in Venezuela and California. Canada has large deposits of tar sands. Currently, production of heavy oil requires large amounts of energy.
Most petroleum is found in sandstone, siltstone or carbonate. Porosities vary from 5% to 30%. The porous rock, covered with an impermeable layer, collects oil from organic matter in lower source rock. It is a process that takes millions of years. The maturation process converts it to a complex mixture of hydrocarbons of about 82 to 87% carbon and 12 to 15% hydrogen. The oil moves into the porous rock in low concentrations with water. To become a reservoir the porous rock must have some type of impermeable cap-rock that traps the oil. Most traps are anticlinal upfolds of strata that are oval shape, however, fault-traps and salt-domes are also common. Oil near the surface often encounters descending meteoric water that brings in oxygen and bacteria that degrade the oil to heavy oil or tar. Oil is usually not found below 4,900 meters because the high temperature of deep rock will degrade the petroleum into natural gas. Therefore, most oil is between 760 m and 4,900 m deep.
Unlike natural gas, the recovery of petroleum oil is not efficient. The existing conventional oil production technologies are able to recover only about one-half of the oil originally in place in a reservoir of light oil. For heavy oil, the recovery is often less than 10%. Tar sands are so heavy that they will not flow at all and no oil can be recovered by conventional drilling and pumping. A technology that could recover a greater percentage of this residual oil could increase oil production from existing reservoirs and reduce the need of the U.S. to imported oil. The additional oil recovered from existing oil producing reservoirs could reduce the need to explore and develop wilderness areas that are potential new oil fields. This additional recovery of existing oil could bridge the gap needed for the development of alternative renewable energy sources.
The Original Oil In Place (OOIP) is the petroleum present in the oil reservoir when first discovered. The volume of the reservoir is determined by the size and porosity of the carbonate or sand stone. The porosity of the rock is a measure of the amount of small chambers or micro-traps within the rock that can hold water or oil. The oil is generally pushed up to the surface with the existing oil reservoir pressures at first. The pressure in the oil well drops with time and there is a need to create overpressure with other means such as water injection or a gas injection for secondary recovery of the OOIP. The choice of a specific secondary recovery technique depends on the type of the hydrocarbon accumulation and the nature of the reservoir. Water injection or “water sweep” or “waterflooding” is a common secondary recovery technique. In waterflooding, pressurized water is injected into the oil-bearing formation rock. Ideally, the injected water displaces the residual oil and moves it to a producing well. Generally in waterflooding, crude oil free of water is recovered first, and then subsequently a mixture of crude oil and water are recovered from the production wells. At some point, the percentage of water in the oil-water mixture (referred to as the water cut) from this technique becomes so high that it is uneconomical to continue pumping oil from the well. The problem, with using water as a “drive fluid”, is that water and oil are immiscible. The lower viscosity water will flow over the oil and by-pass large amounts of oil. Therefore, even after secondary recovery, a significant portion of crude oil remains in the formation, in some cases up to 75% of the OOIP. The fraction of unrecoverable crude oil is typically highest for heavy oils, tar, and large complex hydrocarbons. In the U.S. this residual OIP in old oil wells could be as much as 300 billion barrels of light oil. World-wide, the estimate of unrecoverable oil is 2 trillion barrels. There are an additional 5 trillion barrels of heavy oil, most of which is unrecoverable. Much of this remaining oil is in micro-traps due to capillary forces or adsorbed onto mineral surfaces (irreducible oil saturation) as well as bypassed oil within the rock formation.
Enhanced Oil Recovery
Oil recovery by injection of fluids not normally found in the reservoir is referred to as Enhanced Oil Recovery (EOR). It is a subset of Improved Oil Recovery (IOR), which can include operational strategies such as infill drilling and horizontal drilling. Although it is sometimes referred to as tertiary recovery, it can be implemented along with secondary processes. Many types of EOR have been proposed and used over the years. Technical complexity and the high cost of chemicals have prevented the widespread use of EOR to where it only represents about 10% of total United States oil production.
There have been two major EOR approaches; thermal and non-thermal.
Thermal Processes
Thermal processes work by heating the reservoir rock and the oil to reduce viscosity of the heavy oil. In general, the lower the viscosity of the oil, the better its recovery will be. The most widely used thermal process is steam injection in which the temperature of the reservoir and the remaining oil is increased by heat energy of steam. Hot water may also be used, but it is not as efficient at transferring heat to the oil and rock in the reservoir. Unfortunately, in both processes, most of the heat energy is lost to the surroundings and does not go to heating the oil. In situ combustion of the oil is much more efficient than steam because it only heats the reservoir and not all the pipes and overburden rock. However, in situ combustion is difficult to control and is seldom used. Typically, it requires the energy equivalent of a half a barrel of oil to recover a barrel of oil with a steam injected thermal process. However, this depends on the oil saturation and the configuration of the reservoir. Because most of the energy carried by the steam is given up to the pipes, wall rock, and reservoir, it is best to use only on reservoirs with a high oil content so as to recover as much oil as possible with the steam used to heat the reservoir rock. Generally, thermal methods are used on heavy oil because it reduces the viscosity of the oil and increases the mobility of the oil and the mobility ratio (mobility of displacing fluid to mobility of displaced fluid or oil). Typically, recoveries are in the range of 50 to 60% for a thermal process, but the net energy gain is much less than that because of the large amount of energy needed to make steam.
Non-Thermal Processes
Several non-thermal processes have been experimented with or used over the years. These rely on a combination of reducing the oil viscosity and decreasing the interfacial tension (IFT) between the oil and displacing fluid. Ideally, the mobility of the displacing fluid should not be higher than the oil. The mobility ratio (mobility of displacing fluid over mobility of displaced fluid) should be low. The mobility of the oil can be increased by viscosity reduction and by IFT reduction. As the IFT is decreased, the oil becomes more miscible with the fluid until it becomes one phase and the IFT is zero. This decreases the mobility ratio and increases the oil recovery. Alternatively, the viscosity of the displacing fluid can be increased by adding polymers to “thicken” the liquid. Non-thermal methods require less energy and are best suited for light oil of 100 cp or less. However, most non-thermal methods require considerable laboratory experimentation and process optimization.
Microbial Enhanced Oil Recovery (MEOR)
One special type of EOR technique uses microorganisms such as bacteria and archaea to dislodge the micro-trapped or adsorbed oil from the rock. The goal of this technique, which is known as microbial enhanced oil recovery (MEOR), is to increase oil recovery of the original subsurface hydrocarbons using bacteria rather than the more costly chemical recovery processes. These biological processes typically use microorganisms to achieve similar results as the chemical methods in that they reduce IFT and reduce the mobility ratio of the water drive fluid to oil. The major mechanisms that microbes are believed to operate by are they: (1) alter the permeability of the subterranean formation by producing low molecular weight acids from the biodegradation of hydrocarbons which cause rock dissolution, (2) produce biosurfactants that can decrease IFT and form micelles of oil in water, (3) mediate changes in wet-ability of the oil droplet by growing on the droplet and changing the surface of the oil to a less hydrophobic surface (4) produce bio-polymers that improve the mobility ratio of water to petroleum by increasing the viscosity of water and plug high flow channels, (5) produce lower molecular weight hydrocarbons by enzymatically cleaving the large hydrocarbons into smaller molecules, and thereby reduce the oil's viscosity, (6) generate gases (predominantly carbon dioxide and nitrogen) that increase formation pressure.
Of all the EOR processes, MEOR is presently considered the lowest cost approach, but is generally the least often used. The main reason this biological process is not more widely used, is that it is not always successful or predicable. Furthermore, bacteria in oil wells, pipes and tanks are known to cause problems. In fact, it is believed that high viscosity heavy oil such as oil sands are the result of bacteria consuming the lighter weight petroleum components and leaving behind the high molecular weight fractions which are less readily consumed by the bacteria. Therefore many petroleum engineers see bacteria as a problem, not a solution. In fact, if not used correctly, the growth of bacteria could degrade the oil or increase the hydrogen sulfide concentration in the reservoir.
Numerous microorganisms have been proposed for achieving various microbial objectives in subterranean formations. Early MEOR techniques involved injection of an exogenous microbial population into old and low producing oil wells. The inoculating culture was supplied with nutrients and mineral salts as additives to the water pumped into wells for oil recovery. The development of exogenous microorganisms has been limited by the conditions that prevail in the formation. Physical constraints, such as the small and variable formation pore sizes together with the high temperature, salinity and pressure of fluids in the formation and the low concentration of oxygen in the formation waters severely limit the types and number of microorganisms that can be injected and thrive in the formation. Later, it became apparent that indigenous microbes stimulated by the nutrients were playing the major role in oil recovery. Accordingly, many attempts at biological oil recovery do not inject bacteria at all, but rely on indigenous microorganisms exiting in the extreme environment of the oil reservoir.
Biological constraints, such as competition from indigenous microbes and the stress of changing environments (from surface to subsurface) also act to limit the viability of exogenous microorganisms. To overcome these problems, the use of indigenous microorganisms, commonly anaerobic, has been proposed in MEOR projects. It is known that bacteria and other microbes that can grow indigenously within petroleum oil reservoirs and can be used to enhance oil production. It is also known that bacteria and other microbes will metabolize various components of petroleum as a carbon and energy source. In addition to the beneficial effects of making surfactants, solvents and other metabolites that can result in an increase in oil production; they can also consume oil as a carbon source. Unfortunately, they especially prefer to consume the short-length alkanes, not the heavy viscous oil.
In fact, the process of petroleum bio-degradation relies on the emulsification of oil so that the hydrocarbon can be transported into the bacterial cells for conversion to fatty acids as a carbon and energy source. This process can be used to remediate oil spills and other oil contaminated sites by supplying the indigenous microbes with nutrients or inoculating with cultures of microbes that can degrade oil. In the case of biological remediation of petroleum contaminated sites, microbes can produce metabolites such as surfactants that help emulsify oil so that they can then use the emulsified oil as a carbon source. The process of petroleum bio-degradation relies on the emulsification of oil so that the hydrocarbon can be transported into the cell for conversion to fatty acids as a carbon and energy source. Both of these functions help remove the hydrocarbon contamination from the site. However, in the case of MEOR only the production of metabolites such as surfactants, bio-polymers, hydrocarbon cleaving enzymes, organic acids and solvents are beneficial to increased oil production. Other than providing an energy source, the consumption of light petroleum is not beneficial to enhanced oil production from the reservoir.
The biodegradation of the shorter carbon alkane chains reduces the lighter fraction of the hydrocarbon mixture in the petroleum oil. The removal of the short chain alkanes from this mixture increases the overall viscosity of the hydrocarbon mixture. The higher viscosity is more difficult to recover from the reservoir. The percent of recoverable oil is decreased. Also the oil that is recovered is more difficult to transport through pipes and to refine. Therefore the production of useful compounds, by microbes for improved oil recovery, comes with a high cost.
The process of stimulating all the indigenous microbes in an oil reservoir by adding nutrients is therefore unpredictable. The growth of the microbes could produce the beneficial effect of dislodging oil entrapped within a petroleum reservoir. Alternatively, the side effect of light oil consumption could make the oil more viscous and lower the total recovery of oil.
It would be less detrimental if all petroleum components were degraded equally, but the case is that the shorter chain alkanes and lower molecular weight aromatics are more readily degraded by the microbes as a carbon and energy source. This is supported by the fact that petroleum deposits near the surface and most subject to biodegradation are generally very high in high viscosity oil made up of high levels of asphaltic hydrocarbon and fairly low on light (short) chain alkanes. Canadian tar sands are believed to be the heavy residue representing about 10% of the petroleum deposit that has been degraded.
In the past, others have taught ways of augmenting the growth of microbes that dislodge and mobilize oil from underground petroleum reservoirs. These methods generally recommend adding nutrients. Some have also taught adding various cultures of selected bacteria that added beneficial capabilities. Some have even reported isolating microbes that can only degrade higher molecular weight hydrocarbons (U.S. Pat. No. 5,013,654). However, adding these selected cultures is not enough. Although these prior methods disclosed that microbes exist that can only feed on high molecular weight oil, they failed to provide methods of increasing the bio-digestion of heavy oils, while suppressing the lighter weight hydrocarbon consumption by other indigenous microbes. The microbes that were simply residing within the petroleum reservoir are likely to have the ability to degrade lower weight oil. Adding needed nutrients would stimulate the growth of all the microbes present. Because the smaller hydrocarbons can be transported across the cell membrane, the light weight oil consumers will grow faster than the high weight oil consumers and predominate in the population that results from stimulation.
The prior art does not teach methods that prevent the faster biodegradation of the light weight low-viscosity oil in comparison to the slower biodegradation of the higher weight viscous oil. Therefore, the same process that is beneficial to oil recovery is also detrimental to oil viscosity; and it is known that increasing the viscosity of the residual petroleum held within the reservoir will decrease oil recovery. Therefore, prior methods of adding nutrients, either with or without specially selected or engineered microbes, are unpredictable in terms of their ability to increase oil production.
Accordingly, there is a great need for new enhanced oil recovery approaches that are energy efficient, and can be reliably and successfully used in large field situations to enable the recovery of currently unrecoverable oil in existing oil fields.